1. Field of the Invention
The present invention relates to annulus pressure control drilling systems and methods.
2. Description of the Related Art
The exploration and production of hydrocarbons from subsurface formations ultimately requires a method to reach and extract the hydrocarbons from the formation. This is typically achieved by drilling a well with a drilling rig. In its simplest form, this constitutes a land-based drilling rig that is used to support and rotate a drill string, comprised of a series of drill tubulars with a drill bit mounted at the end. Furthermore, a pumping system is used to circulate a fluid, comprised of a base fluid, typically water or oil, and various additives down the drill string, the fluid then exits through the rotating drill bit and flows back to surface via the annular space formed between the borehole wall and the drill bit. This fluid has multiple functions, such as: to provide pressure in the open wellbore in order to prevent the influx of fluid from the formation, provide support to the borehole wall, transport the cuttings produced by the drill bit to surface, provide hydraulic power to tools fixed in the drill string and cooling of the drill bit.
Clean drilling fluid is circulated into the well through the drill string and then returns to the surface through the annulus between the wellbore wall and the drill string. In offshore drilling operations, a riser is used to contain the annulus fluid between the sea floor and the drilling rig located on the surface. The pressure developed in the annulus is of particular concern because it is the fluid in the annulus that acts directly on the uncased borehole.
The fluid flowing through the annulus, typically known as returns, includes the drilling fluid, cuttings from the well, and any formation fluids that may enter the wellbore. After being circulated through the well, the drilling fluid flows back into a mud handling system, generally comprised of a shaker table, to remove solids, a mud pit and a manual or automatic means for addition of various chemicals or additives to keep the properties of the returned fluid as required for the drilling operation. Once the fluid has been treated, it is circulated back into the well via re-injection into the top of the drill string with the pumping system.
The open wellbore extends below the lowermost casing string, which is cemented to the formation at, and for some distance above, a casing shoe. In an open wellbore that extends into a porous formation, deposits from the drilling fluid will collect on wellbore wall and form a filter cake. The filter cake forms an important barrier between the formation fluids contained in the permeable formation at a certain pore pressure and the wellbore fluids that are circulating at a higher pressure. Thus, the filter cake provides a buffer that allows wellbore pressure to be maintained above pore pressure without significant losses of drilling fluid into the formation.
Both temperature and pressure of subsurface formations increase with depth. Subsurface formations may be characterized by two separate pressures: pore pressure and fracture pressure. The fracture pressure is determined in part by the overburden acting at a particular depth of the formation. The overburden includes all of the rock and other material that overlays, and therefore must be supported by, a particular level of the formation. In an offshore well, the overburden includes not only the sediment of the earth but also the water above the mudline. The pore pressure at a given depth is determined in part by the hydrostatic pressure of the fluids above that depth. These fluids include fluids within the formation below the seafloor/mudline plus the seawater from the seafloor to the sea surface.
In order to maximize the rate of drilling and avoid formation fluids entering the well, it is desirable to maintain the bottom hole pressure (BHP) in the annulus at a level above, but relatively close to, the pore pressure. Maintaining the BHP above the pore pressure is referred to as overbalanced drilling. As BHP increases, drilling rate will decrease, and if the BHP is allowed to increase to the point it exceeds the fracture pressure, a formation fracture can occur. Pressures in excess of the formation fracture pressure FP will result in the fluid pressurizing the formation walls to the extent that small cracks or fractures will open in the borehole wall and the fluid pressure overcomes the formation pressure with significant fluid invasion. Fluid invasion can result in reduced permeability, adversely affecting formation production. Once the formation fractures, returns flowing in the annulus may exit the open wellbore thereby decreasing the fluid column in the well. If this fluid is not replaced, the wellbore pressure can drop and allow formation fluids to enter the wellbore, causing a kick and potentially a blowout. Therefore, the formation fracture pressure defines an upper limit for allowable wellbore pressure in an open wellbore. The pressure margin between the pore pressure and the fracture pressure is known as a window.
The drilling fluid typically has a fairly constant density and thus the hydrostatic pressure in the wellbore versus depth can typically be approximated by a single gradient starting at the top of the fluid column. In offshore drilling situations, the top of the fluid column is generally the top of the riser at the surface platform. The pressure profile of a given drilling fluid varies depending upon whether the drilling fluid is being circulated (dynamic) or not being circulated (static). In the dynamic case, there is a pressure loss as the returns flow up the annulus between the drill string and wellbore wall. This pressure loss adds to the hydrostatic pressure of the drilling fluid in the annulus. Thus, this additional pressure must be taken into consideration to ensure that annulus pressure is maintained in an acceptable pressure range between the pore pressure and fracture pressure profile.
FIG. 1A is an exemplary diagram of the use of fluids during the drilling process in an intermediate borehole section. The borehole has been lined with a string of casing C to a first depth DC. The open hole section to be drilled is thus from the first depth DC to a target depth D4 of the bore hole. The two drilling fluid pressure profiles are represented by the static pressure SP and dynamic pressure DP profiles. The static pressure SP maintained by the fluid during drilling will be safely above the pore pressure PP above a second depth D2. At the second depth D2, the pore pressure PP increases, thereby reducing the differential between the pore pressure PP and the static pressure SP and also decreasing the margin of safety during operations. This may occur where the borehole penetrates a formation interval D2-D4 having significantly different characteristics than the prior formation DC-D2. A gas kick in this interval D2-D4 may result in the pore pressure exceeding the annulus pressure with a release of fluid and gas into the borehole, possibly requiring activation of the surface BOP stack. As noted above, while additional weighting material may be added to the fluid, it will be generally ineffective in dealing with a gas kick due to the time required to increase the fluid density as seen in the borehole.
For the given open hole interval DC-D4, the window for a particular density drilling fluid lies between the pore pressure profile PP and the fracture pressure profile FP. Because the dynamic pressure DP is higher than the static pressure SP, it is the dynamic pressure which is limited by the fracture pressure FP at a third depth D3. Correspondingly, the lower static pressure SP must be maintained above the pore pressure PP at the second depth D2 in the open wellbore. Therefore, the window for the particular density drilling fluid, as shown in FIG. 1, is limited by the dynamic pressure DP reaching fracture pressure FP at the depth D3 and the static pressure SP reaching pore pressure PP at the depth D2. Thus, in common drilling practice, the density of the drilling fluid will be chosen so that the dynamic pressure is as close as is reasonable to the fracture pressure. This maximizes the depth that can then be drilled using that density fluid. Once the dynamic pressure DP pressure approaches fracture pressure at the depth D3, another string of casing will be set and the same process repeated.
Recently, oil exploration and production is moving towards more challenging environments, such as deep and ultra-deepwater. Also, wells are now drilled in areas with increasing environmental and technical risks. In this context, narrow windows between the pore pressure and the fracture pressure of the formation are problematic.
FIG. 1B illustrates a prior art casing program for drilling a narrow-margin wellbore. Since this is a pressure gradient graph, constant density drilling fluids appear as vertical lines. On the right are the number and diameter of the casing strings required to safely drill a wellbore. Typically a safety margin is added to the pore pressure to allow for stopping circulation of the fluid and subtracted from the fracture pressure, reducing even more the narrow window, as shown by the dotted lines. Since the plot shown in FIG. 1B is referenced to the static mud pressure, the safety margin allows for the dynamic effect while drilling also. The pore pressure gradient and fracture pressure gradient curves shown are estimated before drilling. Actual values might never be determined by the current conventional drilling method. It is not difficult to imagine the problems created by drilling in a narrow window, with the requirement of several casing strings, increasing tremendously the cost of the well. Moreover, the current well design shown in FIG. 1B does not reach the required target depth for production, since the last casing size will be too small to allow for a sufficiently sized production tubing string which will deliver oil to the surface at a sufficient flow rate to justify the cost of drilling and completing the well. In many of these cases, the wells are abandoned, leaving the operators with huge losses.
These problems are further compounded and complicated by the density variations caused by temperature changes along the wellbore, especially in deepwater wells. This can lead to significant problems, relative to the narrow window, when wells are shut in to detect kicks/fluid losses. The cooling effect and subsequent density changes can modify the annulus pressure profile due to the temperature effect on mud viscosity, and due to the density increase leading to further complications on resuming circulation. Thus using the conventional method for wells in ultra deep water is rapidly reaching technical limits.
The influx of formation fluids into the wellbore is referred to as a kick. Even when using conservative overbalanced drilling techniques, the wellbore pressure may fall out of the acceptable range between pore pressure and fracture pressure and cause a kick. Kicks may occur for reasons, such as drilling through an abnormally high pressure formation, creating a swabbing effect when pulling the drill string out of the well for changing a bit, not replacing the drilling fluid displaced by the drill string when pulling the drill string out of the hole, and, as discussed above, fluid loss into the formation. A kick may be recognized by drilling fluids flowing up through the annulus after pumping is stopped. A kick may also be recognized by a sudden increase of the fluid level in the drilling fluid storage tanks. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, this influx is known as a blowout and may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig.
There are two commonly used methods for controlling kicks, namely the driller's method and the engineer's method. In both methods the well is shut in and the wellbore pressure allowed to stabilize. The pressure will stabilize when the pressure at the bottom of the hole equalizes with formation pressure. The pressure indicated at the surface in the drill string and the casing annulus can be used to calculate the pressure at the bottom of the wellbore. With the well in the shut-in condition, the pressure at the bottom of the wellbore will be the formation pressure.
When using the driller's method, once the wellbore pressure has stabilized, the pumps are restarted and drilling fluid is circulated through the well. The pressure within the casing is maintained so that no additional formation fluids flow into the well and fluid is circulated until any gas that has entered the wellbore has been removed. A higher density drilling fluid is then prepared and circulated through the well to bring the wellbore pressures back to within the desired pressure range. Thus, when killing a kick using the driller's method, the fluid within the wellbore is fully circulated twice.
When using the engineer's method, as the wellbore pressure stabilizes, the formation pressure is calculated. Based on the calculated formation pressure, a mixture of higher density drilling fluid is prepared and circulated through the well to kill the kick and circulate out any formation fluids in the wellbore. During this circulation, the annulus pressure is maintained until the heavy weight drilling fluid circulates completely through the well. Using the engineer's method, the kick can be killed in a single circulation, as opposed to the two circulation driller's method.
The key parameter for well control is determining the formation pressure and adjusting the annulus pressure profile accordingly. If the annulus pressure is allowed to decrease below the pore pressure at a certain depth, formation fluids will enter the well. If the annulus pressure exceeds fracture pressure at a certain depth, the formation will fracture and wellbore fluids may enter the formation. Conventionally, the BHP is calculated using drill pipe and annulus pressures measured at the surface. To accurately measure these surface pressures; circulation is normally stopped to allow the BHP to stabilize and to eliminate any dynamic component of the annulus pressure. Once this occurs, the well is fully shut in. Shutting the well in uses valuable rig time and involves a drilling stoppage, which may cause other problems, such as a stuck drill string.
Some drilling operations seek to determine a wellbore pressure (i.e., annulus pressure and/or pore pressure) using measurement while drilling (MWD) techniques. One deficiency of the prior art MWD methods is that many tools transmit pressure measurement data back to the surface on an intermittent basis. Many MWD tools incorporate several measurement tools, such as gamma ray sensors, neutron sensors, and densitometers, and typically only one measurement is transmitted back to the surface at a time. Accordingly, the interval between pressure data being reported may be as much as two minutes.
Transmitting the data back to the surface can be accomplished by one of several telemetry methods. One typical prior art telemetry method is mud pulse telemetry. A signal is transmitted by a series of pressure pulses through the drilling fluid. These small pressure variances are received and processed into useful information by equipment at the surface. Mud pulse telemetry systems exhibit low bandwidths, for example between about two-tenths of a bit and about ten bits per second. Further, the velocity of sound through mud varies from about three thousand three hundred feet per second to about five thousand feet per second, meaning that the pulse could take several seconds to travel from the bottom of a deep well to the surface. Further, attenuation is significant for higher frequency pulses. Mud pulse telemetry does not work or does not work well when fluids are not being circulated, are being circulated at a slow rate, and/or when gasified drilling fluid is used. Therefore, mud pulse telemetry and therefore standard MWD tools have very little utility when the well is shut in and fluid is not circulating.
Although MWD tools can not transmit data via mud pulse telemetry when the well is not circulating, many MWD tools can continue to take measurements and store the collected data in memory. The data can then be retrieved from memory at a later time when the entire drilling assembly is pulled out of the hole. In this manner, the operators can learn whether they have been swabbing the well, i.e. pulling fluids into the borehole, or surging the well, i.e. increasing the annulus pressure, as the drill string moves through the wellbore.
Another telemetry method of sending data to the surface is electromagnetic (EM) telemetry. A low frequency radio wave is transmitted through the formation to a receiver at the surface. EM telemetry systems also exhibit low bandwidths, for example about seven bits per second. EM telemetry is depth limited, and the signal attenuates quickly in water. Therefore, with wells being drilled in deep water, the signal will propagate fairly well through the earth but it will not propagate through the deep water. Accordingly, for deep water wells, a subsea receiver would have to be installed at the mud line, which may not be practical. Further, certain formations, i.e., salt domes, also serve as EM barriers.
Thus, there remains a need in the art for methods and apparatuses for measuring and controlling annulus pressure (i.e., BHP) based on real-time pressure data received from a location at or near an open hole section of a wellbore being drilled.